A coupled geomechanical reservoir simulation analysis of carbon dioxide storage in a saline aquifer in the Ohio River Valley

Numerical simulation and optimization of CO2-enhanced water recovery by employing a genetic algorithm

The saline aquifer is the most reliable place where anthropogenic carbon dioxide gas storage has shown a promising future. This paper evaluates and predicts the capacities of different carbon dioxide storage trapping mechanisms in storing carbon dioxide gas in low porosity and permeability deep saline aquifers by using commercial reservoir simulator software i.e., Computer modeling group (CMG). Four carbon dioxide storage trapping modeled and simulated were structural or stratigraphic trapping mechanisms, residual trapping mechanisms, solubility trapping mechanisms, and mineral trapping mechanisms. Carbon dioxide gas was injected into a deep saline aquifer for 15 years, followed by 833 years of post-injection. To reflect the real field reality and have a reasonable approximation of the amount of carbon dioxide which can be stored in an aquifer, this paper included water vaporization effects that occur during carbon dioxide injection and water injection operations so as to optimize residual and solubility trapping mechanisms as the most important trapping mechanisms. Furthermore, the effects of different important parameters such as salinity, vertical-to-horizontal permeability ratio, injection rate, bottom hole pressure, and temperature on each carbon dioxide trapping mechanism were analyzed. Results revealed that each carbon dioxide trapping mechanism has a different capacity for storing carbon dioxide and could be either affected linearly or nonlinearly with various parameters. Higher aquifer temperatures are not recommended for carbon dioxide storage because most of the carbon dioxide gas is stored as free gas, which increases the risk of leakage in case of mechanical failure or imbalance. Excess salinity is the only factor that reduces aquifer storage capacity. Furthermore, it was found that an aquifer with a lower vertical-to-horizontal permeability ratio is recommended for carbon dioxide storage because it increases carbon dioxide stored in an immobile phase, which avoids risk leakages. There was an increase of 43.2% and a decrease of 16.84% for minimum and maximum vertical-to-horizontal permeability (kv/kh) ratios, respectively, compared to the base for residual trapping mechanisms. Also, there was a decrease of carbon dioxide dissolved by 19% at maximum kv/kh ratios and an increase of 58% at minimum kv/kh ratios, compared to the base case. Further, there was an increase of carbon dioxide trapped by 96.4% and dissolved by 97% when water was injected at a higher rate compared to the base case (no water injection). Thus, a high injection rate is suggested to enhance residual and solubility trapping mechanisms. It is recommended that the carbon dioxide injection rate and bottom hole pressure be kept at optimal levels to avoid mechanical failure due to aquifer pressures building up, which can increase the risk of leakages and must be monitored and controlled at the surface using pressure gauges or sensor technology.

Carbon capture and storage, that is the collection of carbon dioxide (CO2) from power plants and its injection underground, is an important technology for reducing CO2 emissions to the atmosphere and hence, mitigating climate change. A key aspect of CO2 storage is the injection rate into the subsurface, which is limited by the pressure at which formation starts to fracture. Hence, it is vital to assess all of the relevant processes that may contribute to the pressure increase in the aquifer during CO2 injection. The central aim of this study is to analyse the ability of the near-well region of a saline formation to conduct fluids, using a set of analytical solutions that enable quick and reliable assessment of CO2 injectivity. In this research, the near-well fluid flow was assumed to be a function of the non-Darcy flow parameter as defined by the Forchheimer equation. For the analysis of single-phase flow problems, the analytical solution for the Forchheimer flow in closed domains was derived and an alternative method for applying analytical solutions associated with a single well to multiple well systems was proposed. The CO2 injection process was modelled as a two-phase system where the non-Darcy flow was assumed for the gas phase only, including a novel representation of the spatially varying fractional flow function. The solution for immiscible flow was further developed to model compositional displacements, which enabled analysis of the porosity reduction due to salt precipitation in a near-well region. Finally, the effects of gas compressibility were examined by integrating the analytical model with an iterative algorithm for correcting gas properties. Results showed that in low permeability formations when CO2 is injected at high rates non-Darcy flow conditions are more favourable for CO2 storage than linear flow due to better displacement efficiency. This, however, came at the cost of increased well pressures. More favourable estimations of the pressure buildup were obtained when CO2 compressibility was taken into account because reservoir pressures were reduced due to the change in the gas phase properties. The non-Darcy flow resulted in a significant reduction in solid salt saturation values, with a positive effect on CO2 injectivity. In the examples shown, non-Darcy flow conditions may lead to significantly different pressure and saturation distributions in the near-well region, with potentially important implications for CO2 injectivity.

Effect of initial water saturation on the performance of fracturing fluids with and without polyallylamine under simulated EGS conditions

A parametric study of coal mass and cap rock behaviour and carbon dioxide flow during and after carbon dioxide injection

Fracturing modeling methods developed for conventional hydraulic fracturing are now being used for unconventional fracturing in waterfracs, water or steam flooding, produced water reinjection, etc. A common feature of these unconventional fracturing processes is the strong interaction among fracture propagation (often with high 3D fluid leakoff), reservoir flow, changes in stresses (poroelastic and thermoelastic effects), and permeability and porosity changes (geomechanical effects) around the fracture. Conventional fracturing models are inadequate under such conditions; moreover, they are also disconnected from well performance forecasting, which makes integrated data analysis difficult. Therefore, it is necessary to seek a new modeling concept including all these mechanisms and their mutual influences. This paper describes a method to model hydraulic fracturing with dynamic transmissibility multipliers based on coupled reservoir and geomechanics simulation. The method is the first step in developing a fracturing model fully coupled into reservoir and geomechanics simulation, where the fracture geometry will be also internally calculated from the fracture face displacements in the coupled FEM geomechanical module. The method described here ignores fracture volume but focuses on the effect of fracture on fluid flow and geomechanics in reservoir by introducing pressure/stress dependent dynamic transmissibility multipliers and treating them as a property of the matrix. This approach allows modeling fracture propagation, dynamical multiphase fracture conductivity, clean-up, and pre- and post-frac well performance in a changing stress, pressure and temperature environment, all in a unified manner. This paper also discusses the strategy of coupling hydraulic fracture propagation, reservoir and geomchanics simulation, resulting in a method to improve the stability of the dynamic hydraulic fracture propagation in coupled reservoir and geomechanics simulation. The case studies in this paper confirm that the strategy and the method to model dynamic hydraulic fracture propagation coupled with reservoir and geomechanics simulation is feasible, flexible and reliable. It is easy and convenient to implement in conventional reservoir simulators and coupled reservoir and geomechanics simulators (such as GEOSIM).

Study of reservoir rock and caprock integrity in geo-sequestration of carbon dioxide

Carbon Dioxide (CO2) injection in geological formations is a potential solution to control anthropogenic greenhouse gas emissions. Value added processes such as CO2 flooding for enhanced oil/gas recovery and disposal processes such as CO2 injection in saline aquifers are among the most promising sequestration processes. Transport, storage, and sequestration of CO2 in these processes involve dispersion and reaction phenomena in porous media. The overall performance of any CO2 injection project depends on the mechanistic aspects of CO2 interaction with the natural porous system at pore scale, core scale, and the heterogeneity of the geological formations. The physics of transport and sequestration of CO2 for different CO2 injection processes in a pore-level scale is first described. These pore-level events are then related to core-scale (gridscale) coefficients using an advanced upscale theory. At the pore-level, a unit cell consists of different sand grains and the interstitial space around them. CO2 enters the unit cell by convection and diffusion and interacts with the interstitial fluid and sand grains. Such local events are transformed into a macro-scale level by adopting periodic boundary conditions for contiguous unit-cells and applying Taylor-Aris dispersion theory. Using this theory, macroscopic coefficient for the transport of CO2 molecules in porous media are determined. These macroscopic coefficients may be used in dispersionreaction constitutive equation to calculate CO2 concentration in time and space. Introduction The three main options for the geological storage of CO2 are saline aquifers, and existing oil and gas fields. These can be divided into two economic end-members. First are purely storage options, whereby the CO2 is injected without any direct financial benefits, e.g. saline aquifers, although carbon tax credits may improve the financial viability of this option. The second are utilization options where the CO2 injection process has additional economic benefits through enhanced hydrocarbon recovery(1). Many of the oil and gas pools in North America have reached the maturity of economic production. CO2 injection is an option to rejuvenate oil or gas production from these reservoirs(2). Miscibility of CO2 and oil improves microscopic displacement efficiency in these pools(3,4). Saline aquifers are defined as aquifers without potable water. Saline aquifers have the potential to store a huge volume of the total CO2 emissions in various locations near the sources of the CO2 emission, e.g. power plants(5–7). For any CO2 storage or utilization process to be successful, it must be technically and economically feasible, effective in significantly reducing CO2 emission for a long period of time, and be safe for people and environment. Reliable mathematical models are needed to predict the success of a CO2 sequestration process in geological formations. The efficiency of a CO2 sequestration process is defined as: Equation (1) (Available in full paper) Mathematical Modelling Suppose that CO2-free fluid flows through the porous bed. At time t=0 let a swarm of CO2 molecules be instantaneously introduced into the bed. Each CO2 molecule will be transported through the interstices by convection and diffusion, with some being interacting (ab/adsorption, reaction) with the interstitial fluid and sand grains.

This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution. Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field. Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process. This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance for a safe and long-term CO2 sequestration.

This paper aims to understand the interplay between injection rate, water vaporization, and capillary backflow on halite precipitation when injecting dry CO2 into a saline aquifer, and the potential injectivity impairment. Key processes affecting salt precipitation include two-phase displacement of brine, dry-out and capillary-driven backflow. In this work, we developed 1D and 2D thermal-compositional radial models with fine gridding around the wellbore and strongly controlled timesteps to study the effects of CO2 injection at different rates using a commercial reservoir simulator (GEM). The initial reservoir conditions were 300 bars, 109 °C, and salinity of 49 g/L. We applied a porosity-permeability relationship from the Verma and Muller (1988) model, which implies complete permeability reduction when porosity decreases by 9%. Simulations were performed with and without capillary pressure effects. After performing some sensitivities to the grid-block size, a fine grid resolution (0.1-0.2 m) near the well is needed at relative low CO2 injection rates due to capillary effects. While less critical at high injection rates, grid refinement still influences precipitation onset at higher rates. We found that a 0.2 m near-well grid size offers a practical balance between accuracy and computational efficiency when simulating salt precipitation during the CO2 injection in saline aquifer. The 1D results show that at zero capillary pressure, impairment is independent of the injection rate, with only 1% of pore volume occupied by salt precipitation, corresponding to the salt mass contained in the immobile brine. However, with non-zero capillary pressure, capillarity can cause significant backflow, bringing additional brine to the near-wellbore area, resulting in higher amounts of precipitated salt. High injection rates shorten the exposure time to capillary backflow with rapid water vaporization and less salt precipitation in the wellbore. Conversely, at low injection rates, brine backflow effectively compensates water vaporization, bringing more brine from the reservoir to the well. This increases solid salt accumulation around the wellbore and reduces permeability. An injection rate as low as 0.1 MTPA may block well injectivity due to high solid saturation, whereas an injection rate of 1 MTPA may partially impair injectivity with only 2% solid saturation around the well. Gravity effects on solid precipitation were analysed by modeling CO2 injection in a 2D radial model. More optimistic results were obtained compared to the 1D model, indicating that some level of impairment can be expected in the well section with low injection flow rates. However, other sections can continue injection with weak permeability reduction even when injecting CO2 at 0.1 MTPA. In general, injectivity is partially impaired, but CO2 injection may proceed with some loss of injectivity and higher bottom-hole pressure. A capillary number defined as the ratio of viscous to capillary forces seems effectively to characterize the dominant forces influencing halite precipitation during the dryout period. High capillary numbers (high injection rates) result in minimal impairment, while intermediate values show a balance leading to moderate damage. Low capillary numbers (low injection rates) are associated with strong capillary backflow and severe permeability reduction. The dry-out time is significantly extended at low injection rates due to capillary backflow. The dimensionless capillary number can be used to predict formation damage and injectivity changes for similar reservoir conditions. However, further work is needed to generalize these findings across a wider range of parameters. This study offers valuable insights into halite precipitation mechanisms during CO2 injection in saline aquifers, important for optimizing injection strategies and mitigating well impairment. By understanding the interplay between injection rate, water transport by CO2, and capillary forces, we can better predict and manage salt precipitation risks.

It is now well established that poro-thermo-elastic effects substantially change the magnitude and orientation of in-situ stresses. Fractures induced in injectors during water injection for waterflooding or produced water disposal have a profound impact on waterflooding performance. These effects, coupled with injectivity decline due to plugging caused by injected particles, lead to permeability reduction, fracture initiation and propagation. Models are available for fracture propagation in single injection wells and single layered reservoirs that account for these effects. However, the impact of fluid injection and production on fracture growth in multiple wells and multi-layered reservoirs with competing fractures has not been systematically modelled at a field scale. In this work, a three-dimensional, two-phase flow simulator with iteratively coupled geomechanics has been developed and applied to model the dynamic growth of injection-induced fractures. The model is based on a finite volume implementation of the cohesive zone model for arbitrary fracture propagation coupled with two-phase flow. A dynamic filtration model for permeability reduction is employed on the fracture faces to incorporate effects of internal damage and external filter cake build-up due to the injection of suspended solids and oil droplets. All physical phenomena are solved in a single framework designed for multi-well, field-scale simulation. The pressure distribution, saturation profile, thermal front, mechanical displacements and reservoir stresses are computed as fluids are injected and produced from the reservoir. Simulation results are discussed with single as well as multiple fractures propagating. Stress reorientation due to poroelastic, thermoelastic and mechanical effects is examined for the simulated cases. The orientation of the fractures is controlled primarily by the orientation of the stresses, which in turn depends on the pattern of wells and the rates of injection and production. The sweep efficiency of the waterflood is found to be impacted by the rate of growth of injection-induced fractures. Heterogeneities in multi-layered reservoirs strongly govern the expected vertical sweep and fluid distribution, which impacts the cumulative oil recovery. This is the first time a formulation of multiphase flow in the reservoir has been coupled with dynamic fracture propagation in multiple wells induced by solids plugging while including poro-thermo-elasticity at the reservoir scale. The model developed in this work can be used to simulate multiple water injection induced fractures, determine the reoriented stress state to optimize the location of infill wells and adjust injection well patterns to maximize reservoir sweep.

Modeling of pressure evolution during multiple well injection of CO2 in saline aquifers

Numerical investigation of the formation displacement and caprock integrity in the Ordos Basin (China) during CO2 injection operation

The problem of carbon dioxide utilization is of increasing concern to the public, since measures to reduce greenhouse gas emissions are no longer sufficient to prevent a global increase in temperature on the planet. Most modeling scenarios show that a significant deployment of negative emission technologies is required. Carbon dioxide is often used as an agent for enhancing hydrocarbon production in the development of oil and gas fields, which is technologically consistent with projects for its utilization and underground storage in depleted reservoirs, saline aquifers, and shale rocks. For the successful implementation of such sequestration projects, it is necessary to conduct a complex of experimental, modeling, and field studies. It is necessary to understand the characteristic physical and chemical changes that occur in a subterranean formation during sequestration processes, such as dissolution, chemical reactions, convective mixing, advective processes, and dispersion. Computer modeling of ongoing processes is seen as a very important task for the correct functioning of such projects. The article deals with topical problems of computer modeling of processes associated with underground injection and storage of carbon dioxide, and also presents the results of laboratory studies on the utilization of carbon dioxide through its catalytic conversion into useful energy resources—hydrogen and hydrocarbons. The findings of this study can help to better understand physicochemical mechanisms that can occur in subterranean formations when carbon dioxide is injected. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd.

M4 carbonate field, a depleted gas field located offshore Sarawak, has been identified as potential candidate for CO2 sequestration site in conjunction with another high CO2 field development and commercialization efforts. The field has undergone a feasibility study to evaluate potential geomechanical issues associated with CO2 injection. A detail 3D simulation analysis was conducted to quantify the effective storage capacity in M4 field, identify the optimum CO2 injection scheme and evaluate the trapping mechanism in M4 field. Reservoir geomechanical study was also performed for M4 field to evaluate the associated geomechanical issues pre, during and post CO2 injection to assure a safe and long term CO2 sequestration in the field. First, the available field history matched black oil simulation model was successfully converted to compositional 3D model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. A detail study has then been conducted to understand the containment and analyze the effective CO2 trapping mechanisms. Different types of trapping mechanisms including the hydrodynamic trapping, residual or capillary trapping, solubility trapping, and mineral trapping have been studied in detail. Hysteresis effect on CO2 sequestration and different trapping mechanism during and post CO2 injection has been also studied. In addition, various CO2 injection schemes have been also conducted to optimize the injection rate, sustainability, capacity, location, number of the wells and favorable trapping mechanism for long term sequestration. The study covered 20 years of gas production history and forecast followed by 10 years of CO2 injection in the selected optimum scheme and then monitoring part more than for 100 years after injection to assure the safe sequestration and potential CO2 leakage. Constraining to the initial reservoir pressure to assure cap rock integrity and potential leakages, the study showed that the field has potential to store and sequestrate CO2 up to 40% bigger standard volume than gas initially in place (GIIP). Introduction A feasibility study on CO2 injection and sequestration in depleted gas field was conducted in conjunction with Alpha field development in Malaysia. The Alpha field, a carbonate gas field, is located approximately 250 km offshore, Sarawak, East Malaysia. Based on reservoir fluid analysis, the Alpha field contained approximately 70% CO2 content. Vast CO2 production is expected from the field when it comes into production and as part of CO2 mitigation plan, the produced CO2 will be transported, injected and sequestrated into depleted nearby gas fields. M4 field, a depleting gas field, has been identified as one of the potential candidates for CO2 injection and sequestration site to support Alpha field gas monetization. The M4 field, a carbonate gas condensate reservoir, is part of mega platform carbonate build-up formation that consists of seven fields and is located in Central Luconia province, approximately 250 km offshore Sarawak, East Malaysia [1 – 2], and about 170 km to the North North East (NNE) of the Alpha field (Fig. 1). The field was discovered in 1980 by A-1X exploration well and was later appraised by A-2 well drilled in 1992 with estimated initial reservoir pressure of 3860 psi at Original Gas Oil Contact (OGOC). The field was developed with two horizontal sub-sea wells namely AA-1 and AA-2, positioned at the crest of the reservoir structure, approximately 24 ft below the top of carbonate. Production from the field is tied back to M3 production facility, located approximately 10 km to the South, and first gas production came on stream in 2002.